1. Field of the Invention
This invention relates to a method of increasing the viscosity of carbon dioxide; to new compositions of matter comprising carbon dioxide and a viscosifying amount of a defined polymer-cosolvent mixture; and to a method of recovering oil from underground subterranean formations.
In newly discovered oil fields, oil will usually be recovered by flowing from a producing well under the natural pressure of the fluids present in the porous reservoir rocks. The naturally occurring pressure in the formation decreases as the fluids are removed. This is the so-called primary production and recovers perhaps 5% to 20% of the oil present in the formation.
Secondary recovery methods are used to recover more of the oil, and in these methods a fluid is injected into the reservoir to drive additional oil out of the rocks, e.g., waterflooding. Waterflooding, of course, has its own limitations as it is immiscible with oil and as the water displaces the oil, oil remaining in the reservoir reaches a limiting value known as "the residual oil saturation" and oil no longer flows. There is a strong capillary action which tends to hold the oil in the interstices of the rocks. The amount of oil recovered by secondary techniques is usually from about 5% to 30% of the oil initially present.
In recent years, more attention has been directed to the so-called enhanced recovery or tertiary recovery techniques. While these methods are more expensive, they are justified by the increased price of crude. In general, these tertiary recovery methods are used to recover the residual oil by overcoming the capillary forces which trap oil during waterflooding. For example, it has been suggested to add surfactants to the flood to decrease the interfacial tension and thus allow oil droplets to move to producing wells.
Secondary recovery of oil is also possible by the miscible fluid displacement process. Propane, for example, would be an appropriate material to utilize for it is fully miscible with oil but, in general, propane is far too expensive, except in remote regions such as the Arctic where it is impractical to pipe propane and thus any propane produced in the field could be reinjected to recover more liquid hydrocarbons. Nevertheless, the use of crude oil miscible solvents such as propane to displace crude oil through a formation is well known, as, for example, in the teachings of Morse in U.S. Pat. No. 3,354,953. It is also suggested by Morse that the viscosity of the propane can be "controlled" (i.e., increased) by the addition of kerosene. Henderson et al. teach in U.S. Pat. No. 3,330,345 to use a slug of thickened material such as propane before flooding with an amphipathic solvent. The teachings of Dauben et al. in U.S. Pat. No. 3,570,601 relate to the recovery of oil using viscous propane, where the propane is viscosified by first dissolving a solid polymer such as polyisobutylene in a heavier hydrocarbon, such as heptane, and then diluting this first solution with propane to form the oil-driving bank.
In the continental United States, carbon dioxide is generally less expensive. A number of carbon dioxide floods have been tried in the United States. The CO.sub.2 tends to dissolve in the oil which swells with a consequent decrease in viscosity and improvement in the flow to producing wells. The CO.sub.2 also extracts light hydrocarbons from the oil and this mixture of CO.sub.2 and light hydrocarbons can in some cases reach a composition that will miscibly displace the oil. This CO.sub.2 -rich phase characteristically has a lower viscosity than the oil and tends to finger through the formation. Early CO.sub.2 breakthrough is of course not desired since reservoir sweep is reduced and, also, expensive separation procedures are required to separate and recycle the carbon dioxide. For example, the viscosity of carbon dioxide at usual reservoir pressures and temperatures is on the order of a few hundredths of a centipoise while the oil being displaced may have a viscosity in the range of from 0.1 to 100 centipoises.
It is apparent that an increase in viscosity of carbon dioxide would be helpful in decreasing the mobility of the carbon dioxide and thus increasing the pressure gradient behind the frontal region which would reduce fingering and improve the reservoir sweep.
2. Descriptive of the Prior Art
The prior art describes a number of techniques to control the mobility of carbon dioxide. These techniques are described generally in an article entitled "CO.sub.2 as Solvent for Oil Recovery" by F. M. Orr, Jr. et al. (Chemtech, Aug. 1983, page 42, et seq.). There is the water-alternating-with-gas process where slugs of carbon dioxide are injected alternatively with slugs of water. Also, investigations have been made into the use of polymers to reduce the mobility of carbon dioxide. F. M. Orr, Jr. et al. report in the above article that studies by New Mexico Petroleum Recovery Research Center indicate that only low-molecular weight polymers dissolve in carbon dioxide and, as a result, only 10% to 20% increase in solution viscosity have been observed.
Other studies of the use of polymers for CO.sub.2 thickening appear in "Measuring Solubility of Polymers in Dense CO.sub.2 " by J. P. Heller et al. (Polymer Preprint, Vol. 22(2), 1981, New York ACS Meeting) and especially "Direct Thickeners for Mobility Control of CO.sub.2 Floods" by J. P. Heller et al. (SPE 11789, June 1983). In the latter paper, Heller et al. conclude that the search for polymeric direct thickeners have been "unsuccessful in the purpose of a wide margin." The increase in viscosity observed by Heller et al. was small and in no case greater than 30%, i.e., the ratio of the kinematic viscosity of the CO.sub.2 -polymer solution to the kinematic viscosity of the CO.sub.2 under the same conditions was no greater than 1.3.
Recent work by J. P. Heller and J. J. Taber has been reported in "Development of Mobility Control Methods to Improve Oil Recovery by CO.sub.2 : Final Report," DOE/MC/10689-17 (available from NTIS) where the authors list some 53 polymers which have been tried in an effort to thicken the CO.sub.2 but with little to no success.
Work done by Heller et al. was done with pure dry CO.sub.2 at pressure of 1500 to 3160 psig and temperatures of 25.degree. to 58.degree. C. which would be typical of reservoirs where CO.sub.2 flooding could be carried out. A number of low and high molecular weight polymers were tried, and in general their results showed that high molecular weight polymers were not soluble. Polymers having solubilities above one weight percent (i.e., polybutene, polydecene and polypropylene glycol) all had molecular weights of 400 to 1000. Increasing molecular weight of the polymer led to decreased solubility of the polymer in CO.sub.2. Heller's work suggests that it is not obvious how to find polymers having a molecular weight over 1000 that have any significant solubility in CO.sub.2. It is also difficult and unobvious from the teachings of the prior art on how to substantially increase the viscosity by dissolving very high molecular weight polymers at desirably low concentrations of the polymers. The known poor solvent properties of liquid and supercritical CO.sub.2 compared to the more usual solvents are a limiting factor when it comes to dissolving large molecules such as high molecular weight polymers.
It remains, therefore, a desired objective to find a means to increase the viscosity of carbon dioxide to achieve a viscosity of at least 0.15 centipoises utilizing polymers having a molecular weight about 1000. It has now been found that this objective can be achieved and that viscosity increases for the CO.sub.2 of three-fold to 30-fold or more can be achieved utilizing certain defined cosolvents along with certain defined polymers.